1. Field of the Invention
This invention involves a process for recovering, cracking, hydrogenating, desulfurizing, demetalating, and denitrifying hydrocarbons from oil shale and tar sands.
2. Description of the Prior Art
The potential reserves of liquid hydrocarbons contained in subterranean carbonaceous deposits are known to be very substantial and form a large portion of the known energy reserves in the world. In fact, the potential reserves of liquid hydrocarbons to be derived from oil shale and tar sands greatly exceed the known reserves of liquid hydrocarbons to be derived from petroleum. As a result of the increasing demand for light hydrocarbon fractions, there is much current interest in economical methods for recovering liquid hydrocarbons from oil shale and tar sands on a commercial scale. Various methods of recovery of hydrocarbons from these deposits have been proposed, but the principal difficulty with these methods is their high cost which renders the recovered hydrocarbons too expensive to compete with petroleum crudes recovered by more conventional methods.
Moreover, the value of hydrocarbons recovered from oil shale and tar sands is diminished due to the presence of certain contaminants in the recovered hydrocarbons and the form of the recovered hydrocarbons. The chief contaminants are sulfurous, nitrogenous, and metallic compounds which cause detrimental effects with respect to various catalysts utilized in a multitude of processes to which the recovered hydrocarbons may be subjected. These contaminants are also undesirable because of their disagreeable odor, corrosive characteristics, and combustion products. Also the oil obtained from tar sands is heavier and more viscous than conventional petroleum crudes and has properties resembling those of residual materials. About 50 percent of the hydrocarbon fraction recovered from tar sands boils above 1000.degree. F. and can not be pumped in a conventional crude pipeline because of the relatively high pour point and viscosity.
Additionally, as a result of the increasing demand for light hydrocarbon fractions, there is such current interest in more efficient methods for converting the heavier hydrocarbon fractions recovered from oil shale and tar sands into lighter materials. The conventional methods of converting heavier hydrocarbon fractions into lighter materials, such as catalytic cracking, coking, thermal cracking and the like, always result in the production of more highly refractory materials.
It is known that such heavier hydrocarbon fractions and such refractory materials can be converted to lighter materials by hydrocracking. Hydrocracking processes are most commonly employed on liquefied coils or heavy residual or distillate oils for the production of substantial yields of low boiling saturated products and to some extent of intermediates which are utilizable as domestic fuels, and still heavier cuts which find uses as lubricants. These destructive hydrogenation processes or hydrocracking processes may be operated on a strictly thermal basis or in the presence of a catalyst.
However, the application of the hydrocracking technique has in the past been fairly limited because of several interrelated problems. Conversion by the hydrocracking technique of heavy hydrocarbon fractions recovered from oil shale and tar sands to more useful products is complicated by the presence of certain contaminants in such hydrocarbon fractions. Oils extracted from oil shale and tar sands contain nitrogenous, sulfurous, and organo-metallic compounds in exceedingly large quantities. The presence of sulfur- and nitrogen-containing and organo-metallic compounds in crude oils and various refined petroleum products and hydrocarbon fractions has long been considered undesirable.
For example, because of the disagreeable odor, corrosive characteristics and combustion products (particularly sulfur dioxide) of sulfurcontaining compounds, sulfur removal has been of constant concern to the petroleum refine. Further, the heavier hydrocarbons are largely subjected to hydrocarbon conversion processes in which the conversion catalysts are, as a rule, highly susceptible to poisoning by sulfur compounds. This had led in the past to the selection of low-sulfur hydrocarbon fractions whenever possible. With the necessity of utilizing heavy, high sulfur hydrocarbon fractions in the future, economical desulfurization processes are essential. This need is further emphasized by recent and proposed legislation which seeks to limit sulfur contents of industrial, domestic, and motor fuels.
Generally, sulfur appears in feedstocks in one of the following forms: mercaptans, hydrogen sulfides, sulfides, disulfides, and as part of complex ring compounds. The mercaptans and hydrogen sulfides are more reactive and are generally found in the lower boiling fractions, for example, gasoline, naphtha, kerosene, and light gas oil fractions. There are several well-known processes for sulfur removal from such lower boiling fractions. However, sulfur removal from higher boiling fractions has been a more difficult problem. Here, sulfur is present for the most part in less reactive forms as sulfides, disulfides, and as part of complex ring compounds of which thiophene is a prototype. Such sulfur compounds are not susceptible to the conventional chemical treatments found satisfactory for the removal of mercaptans and hydrogen sulfide and are particularly difficult to remove from heavy hydrocarbon materials.
Nitrogen is undesirable because it effectively poisons various catalytic composites which may be employed in the conversion of heavy hydrocarbon fractions. In particular, nitrogen-containing compounds are effective in suppressing hydrocracking. Moreover, nitrogenous compounds are objectionable because combustion fuels containing these impurities possibly contributes to the release of nitrogen oxides which are noxious and corrosive and present a serious problem with respect to pollution of the atmosphere. Consequently, removal of the nitrogenous contaminants is most important and makes practical and economically attractive the treatment of contaminated stocks.
However, in order to remove the sulfur or nitrogen or to convert the heavy residue into lighter more valuable products, the heavy hydrocarbon fraction is ordinarily subjected to a hydrocatalytic treatment. This is conventionally done by contacting the hydrocarbon fraction with hydrogen at an elevated temperature and pressure and in the presence of a catalyst. Unfortunately, unlike distillate stocks which are substantially free from asphaltenes and metals, the presence of asphaltenes and metal-containing compounds in heavy hydrocarbon fraction leads to a relatively rapid reduction in the activity of the catalyst to below a practical level. The presence of these materials in the charge stock results in the deposition of metal-containing coke on the catalyst particles, which prevents the charge from coming in contact with the catalyst and thereby, in effect, reduces the catalyst activity. Eventually, the on-stream period must be interrupted, and the catalyst must be regenerated or replaced with fresh catalyst.
Particularly objectionable is the presence of iron in the form of soluble organometallic compounds. Even when the concentration of iron porphyrin complexes and the other iron organometallic complexes is relatively small, that is, on the order of parts per million, their presence causes serious difficulties in the refining and utilization of heavy hydrocarbon fractions. The presence of an appreciable quantity of the organometallic iron compounds in feedstocks undergoing catalytic cracking causes rapid deterioration of the cracking catalysts and changes the selectivity of the cracking catalysts in the direction of more of the charge stock being converted to coke. Also, the presence of an appreciable quantity of the organo-iron compounds in feedstocks undergoing hydroconversion (such as hydrotreating or hydrocracking) causes harmful effects in the hydroconversion processes, such as deactivation of the hydroconversion catalyst and, in many instances, plugging or increasing of the pressure drop in fixed bed hydroconversion reactors due to the deposition of iron compounds in the interstices between catalyst particles in the fixed bed of catalyst.
Additionally, metallic contaminants such as nickel- and vanadiumcontaining compounds are found as innate contaminants in hydrocarbon fractions recovered from oil shale and tar sands. When the hydrocarbon fractions is topped to remove the light fractions boiling above about 450.degree.-650.degree. F., the metals are concentrated in the residual bottoms. If the residuum is then further treated, such metals adversely affect catalysts. When the hydrocarbon fraction is used as a fuel, the metals also cause poor performance in industrial furnaces by corroding the metal surfaces of the furnace.
A promising technique for recovering liquid hydrocarbons from tar sands and from oil shale is a process called dense fluid extraction. Separation by dense fluid extraction at elevated temperatures is a relatively unexplored area. The basic principles of dense fluid extraction at elevated temperatures are outlined in the monograph "The Principles of Gas Extraction" by P. F. M. Paul and W. S. Wise, published by Mills and Boon Limited in London, 1971, of which Chapters 1 through 4 are specifically incorporated herein by reference. The dense fluid can be either a liquid or a dense gas having a liquid-like density.
Dense fluid extraction depends on the changes in the properties of a fluid -- in particular, the density of the fluid -- due to changes in the pressure. At temperatures below its critical temperature, the density of a fluid varies in step functional fashion with changes in the pressure. Such sharp transitions in the density are associated with vapor-liquid transitions. At temperatures above the critical temperature of a fluid, the density of the fluid increases almost linearly with pressure as required by the Ideal Gas Law, although deviations from linearity are noticeable at higher pressures. Such deviations are more marked as the temperature of the fluid is nearer, but still above, its critical temperature.
If a fluid is maintained at a temperature below its critical temperature and at its saturated vapor pressure, two phases will be in equilibrium with each other, liquid X of density C and vapor Y of density D. The liquid of density C will possess a certain solvent power. If the same fluid were then maintained at a particular temperature above its critical temperature and if it were compressed to density C, then the compressed fluid could be expected to possess a solvent power similar to that of liquid X of density C. A similar solvent power could be achieved at an even higher temperature by an even greater compression of the fluid to density C. However, because of the non-ideal behavior of the fluid near its critical temperature, a particular increase in pressure will be more effective in increasing the density of the fluid when the temperature is slightly above the critical temperature than when the temperature is much above the critical temperature of the fluid.
These simple considerations lead to the suggestion that at a given pressure and at a temperature above the critical temperature of a compressed fluid, the solvent power of the compressed fluid should be greater the lower the temperature; and that, at a given temperature above the critical temperature of the compressed fluid, the solvent power of the compressed fluid should be greater the higher the pressure.
Although such useful solvent effects have been found above the critical temperature of the fluid solvent, it is not essential that the solvent phase be maintained above its critical temperature. It is only essential that the fluid solvent be maintained at high enough pressures so that its density is high. Thus, liquid fluids and gaseous fluids which are maintained at high pressures and have liquid-like densities are useful solvents in dense fluid extractions at elevated temperatures.
The basis of separations by dense fluid extraction at elevated temperatures is that a substrate is brought into contact with a dense, compressed fluid at an elevated temperature, material from the substrate is dissolved in the fluid phase, then the fluid phase containing this dissolved material is isolated, and finally the isolated fluid phase is decompressed to a point where the solvent power of the fluid is destroyed and where the dissolved material is separated as a solid or liquid.
Some general conclusions based on empirical correlations have been drawn regarding the conditions for achieving high solubility of substrates in dense, compressed fluids. For example, the solvent effect of a dense, compressed fluid depends on the physical properties of the fluid solvent and of substrate. This suggests that fluids of different chemical nature but similar physical properties would behave similarly as solvents. An example is the discovery that the solvent power of compressed ethylene and carbon dioxide is similar.
In addition, it has been concluded that a more efficient dense fluid extraction should be obtained with a solvent whose critical temperature is nearer the extraction temperature than with a solvent whose critical temperature is farther from the extraction temperature. Further since the solvent power of the dense, compressed fluid should be greater the lower the temperature but since the vapor pressure of the material to be extracted should be greater the higher the temperature, the choice of extraction temperature should be a compromise between these opposing effects.
Various ways of making practical use of dense fluid extraction are possible following the analogy of conventional separation processes. For example, both the extraction stage and the decompression stage afford considerable scope for making separations of mixtures of materials. Mild conditions can be used to extract first the more volatile materials, and then more severe conditions can be used to extract the less volatile materials. The decompression stage can also be carried out in a single stage or in several stages so that the less volatile dissolved species separate first. The extent of extraction and the recovery of product on decompression can be controlled by selecting of an appropriate fluid solvent, by adjusting the temperature and pressure of the extraction or decompression, and by altering the ratio of substrate-to-fluid solvent which is charged to the extraction vessel.
In general, dense fluid extraction at elevated temperatures can be considered as an alternative, on the one hand, to distillation and, on the other hand, to extraction with liquid solvents at lower temperatures. A considerable advantage of dense fluid extraction over distillation is that it enables substrates of low volatility to be processed. Dense fluid extraction even offers an alternative to molecular distillation, but with such high concentrations in the dense fluid phase that a marked advantage in throughput should result. Dense fluid extraction would be of particular use where heat-liable substrates have to be processed since extraction into the dense fluid phase can be effected at temperatures well below those required by distillation.
A considerable advantage of fluid extraction at elevated temperatures over liquid extraction at lower temperatures is that the solvent power of the compressed fluid solvent can be continuously controlled by adjusting the pressure instead of the temperature. Having available a means of controlling solvent power by pressure changes given a new approach and scope to solvent extraction processes.
Zhuze was apparently the first to apply dense fluid extraction to chemical engineering operations in a scheme for de-asphalting petroleum fractions using a propane-propylene mixture as gas, as reported in Vestnik Akad. Nauk S.S.S.R. 29 (11), 47-52 (1959) and in Petroleum (London) 23, 298-300 (1960).
Apart from Zhuze's work, there have been few detailed reports of attempts to apply dense fluid extraction techniques to substrates of commercial interest. British Pat. No. 1,057,911 (1964) describes the principles of gas extraction in general terms, emphasizes its use as a separation technique complementary to solvent extraction and distillation, and outlines multi-stage operation. British Pat. No. 1,111,422 (1965) refers to the use of gas extraction techniques for working up heavy petroleum fractions. A feature of particular interest is the separation of materials into residue and extract products, the latter being free from objectionable inorganic contaminants such as vanadium. The advantage is also mentioned in this patent of cooling the gas solvent at subcritical temperatures before recycling it. This converts it to the liquid form which requires less energy to pump it against the hydrostatic head in the reactor than would a gas. French Pat. Nos. 1,512,060 (1967) and 1,512,061 (1967) mention the use of gas extraction on petroleum fractions. In principle, these seem to follow the direction of the earlier Russian work.
In addition, there are other references to recovery of liquid hydrocarbon fractions from carbonaceous deposits by processes utilizing water. For example, Friedman et al., U.S. Pat. No. 3,051,644 (1962) discloses a process for the recovery of oil from oil shale which involves subjecting oil shale particles dispersed in steam to treatment with steam at a temperature in the range of from 700.degree. F. to 900.degree. F. and at a pressure in the range of from 1000 to 3000 pounds per square inch gauge. Oil from the oil shale is withdrawn in vapor form admixed with steam.
Truitt et al., U.S. Pat. No. 2,665,238 (1954) discloses a method of recovering oil from oil shale which involves treating the shale with water in a large amount approaching the weight of the shale, at a temperature in excess of 500.degree. F. and under a pressure in excess of 1000 pounds per square inch. The amount of oil recovered increases generally as the temperature or pressure is further increased, but pressures as high as about 3000 pounds per square inch gauge and temperatures at least approximately as high as 700.degree. F. are required to effect a substantially complete recovery of the oil.
There have been numerous references to processes for cracking, desulfurizing, denitrifying, demetalating, and generally upgrading hydrocarbon fractions by processes involving water. For example, Gatsis, U.S. Pat. No. 3,453,206 (1969) discloses a multi-stage process for hydrorefining heavy hydrocarbon fractions for the purpose of eliminating and/or reducing the concentration of sulfurous, nitrogenous, organometallic, and asphaltenic contaminants therefrom. The nitrogenous and sulfurous contaminants are converted to ammonia and hydrogen sulfide. The stage comprises pretreating the hydrocarbon fraction in the absence of a catalyst, with a mixture of water and externally supplied hydrogen at a temperature above the critical temperature of water and a pressure of at least 1000 pounds per square inch gauge and then reacting the liquid product from the pretreatment stage with externally supplied hydrogen at hydrorefining conditions and in the presence of a catalytic composite. The catalytic composite comprises a metallic component composited with a refractory inorganic oxide carrier material of either synthetic or natural origin, which carrier material has a medium-to-high surface area and a well-developed pore structure. The metallic component can be vanadium, niobium, tantalum, molybdenum, tungsten, chromium, iron, cobalt, nickel, platinum, palladium, iridium, osmium, rhodium, ruthenium, and mixtures thereof.
Gatsis, U.S. Pat. No. 3,501,396 (1970) discloses a process for desulfurizing and denitrifying oil which comprises mixing the oil with water at a temperature above the critical temperature of water up to about 800.degree. F. and at a pressure in the range of from about 1000 to about 2500 pounds per square inch gauge and reacting the resulting mixture with externally supplied hydrogen in contact with a catalytic composite. The catalytic composite can be characterized as a dual function catalyst comprising a metallic component such as iridium, osmium, rhodium, ruthenium and mixtures thereof and an acidic carrier component having cracking activity. An essential feature of this method is the catalyst being acidic in nature. Ammonia and hydrogen sulfide are produced in the conversion of nitrogenous and sulfurous compounds, respectively.
Pritchford et al., U.S. Pat. No. 3,586,621 (1971) discloses a method for converting heavy hydrocarbon oils, residual hydrocarbon fractions, and solid carbonaceous materials to more useful gaseous and liquid products by contacting the material to be converted with a nickel spinel catalyst promoted with a barium salt of an organic acid in the presence of steam. A temperature in the range of from 600.degree. F. to about 1000.degree. F. and a pressure in the range of from 200 to 3000 pounds per square inch gauge are employed.
Pritchford, U.S. Pat. No. 3,676,331 (1972) discloses a method for upgrading hydrocarbons and thereby producing materials of low molecular weight and of reduced sulfur content and carbon residue by introducing water and a catalyst system containing at least two components into the hydrocarbon fraction. The water can be the natural water content of the hydrocarbon fraction or can be added to the hydrocarbon fraction from an external source. The water-to-hydrocarbon fraction volume ratio is preferably in the range from about 0.1 to about 5. At least the first of the components of the catalyst system promotes the generation of hydrogen by reaction of water in the water gas shift reaction and at least the second of the components of the catalyst system promotes reaction between the hydrogen generated and the constituents of the hydrocarbon fraction. Suitable materials for use as the first component of the catalyst system are the carboxylic acid salts of barium, calcium, strontium, and magnesium. Suitable materials for use as the second component of the catalyst system are the carboxylic acid salts of nickel, cobalt, and iron. The process is carried out at a reaction temperature in the range of from about 750.degree. F. to about 850.degree. F. and at a pressure of from about 300 to about 4000 pounds per square inch gauge in order to maintain a principal portion of the crude oil in the liquid state.
Wilson et al., U.S. Pat. No. 3,733,259 (1973) discloses a process for removing metals, asphaltenes, and sulfur from a heavy hydrocarbon oil. The process comprises dispersing the oil with water, maintaining this dispersion at a temperature between 750.degree. F. and 850.degree. F. and at a pressure between atmospheric and 100 pounds per square inch gauge, cooling the dispersion after at least one-half hour to form a stable water-asphaltene emulsion, separating the emulsion from the treated oil, adding hydrogen, and contacting the resulting treated oil with a hydrogenation catalyst at a temperature between 500.degree. F. and 900.degree. F. and at a pressure between about 300 and 3000 pounds per square inch gauge.
It has also been announced that the semi-governmental Japan Atomic Energy Research Institute, working with the Chisso Engineering Corporation, has developed what is called a "simple, low-cost, hot-water, oil desulfurization process" said to have "sufficient commercial applicability to compete with the hydrogenation process." The process itself consists of passing oil through a pressurized boiling water tank in which water is heated up to approximately 250.degree. C., under a pressure of about 100 atmospheres. Sulfides in oil are then separated when the water temperature is reduced to less than 100.degree. C.
Thus far, no one has disclosed the method of this invention for recovering and upgrading hydrocarbon fractions from oil shale and tar sands, which permits operation in at lower than conventional temperatures, without an external source of hydrogen, and without preparation or pretreatment, such as, desalting or demetalation, prior to upgrading the recovered hydrocarbon fraction.